New base 24 august energy news issue 1065 by khaled al awadi

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NewBase August 24 - 2017 - Issue No. 1065 Senior Editor Eng. Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
UAE: Solar rooftops in Dubai double in less than a year
The National - LeAnne Graves
Dubai buildings with solar rooftops have nearly doubled to 435 in only 10 months as the emirate
works to have all rooftops fitted with photovoltaic (PV) panels.
More than 200 new buildings have been equipped with solar power since November with a total
capacity of 15.6 megawatts as part of the Shams Dubai initiative, the Dubai Electricity and Water
Authority (Dewa) said on Wednesday. The initiative, launched in 2015, aims to have solar panels
on all rooftops across the emirate by 2030.
“Shams Dubai allows customers to avoid using very expensive power storage systems by
connecting the PV panels to the network,” said Saeed Al Tayer, the managing director and chief
executive of Dewa.
The power generated from the solar panels will cover the customer’s needs, but under a net
metering system, any surplus power will be fed back into the grid with a credit seen on the
customer’s electricity bill. To help residential and businesses consider solar, Dewa created a solar
calculator last month,located on its website. The calculator helps provide customers with
comparisons to help promote the installation of solar power.
Other tools available to those interested in installing solar panel systems include Green Deal
Dubai, a crowdsourcing platform to help drive down the costs of solar thanks to providing an
aggregated list of providers.
Dubai is targeting to generate 7 per cent of its total power output from clean energy sources by
2020, 25 per cent by 2030 and 75 per cent by 2050. The Dewa-owned Etihad Energy Services
(Esco) installed 144 solar PV panels totaling 37.5 kilowatts on the utility’s centre in Hatta, the
utility announced this week. The company will also add solar PV systems to 640 villas in the area
by the end of the next year.

Saudi Aramco receives bids / contracts in gas expansion drive
Reuters
The contracts are part of a $4b scheme to increase gas production in the country for domestic
consumption. Saudi Aramco has received bids from international engineering companies to build
gas booster compressor stations at Haradh and Hawiyah, industry sources said, as the country
plans to diversify its energy mix.
The contracts are part of a $4 billion scheme to increase gas production in the country for
domestic consumption. Saudi Arabia’s domestic gas demand has been rising mainly due to the
growth of industrial sectors, which the country wants to develop further.
Last week, Asian and European companies submitted bids for the expansion of the Hawiyah gas
plant. Aramco plans to expand the processing capacity at Hawiyah by 1.3 billion standard cubic
feet per day (scfd). It currently processes 2.5 billion scfd of gas.
The companies that have made bids are: South Korean Hyundai Development Co Engineering &
Construction (HDEC), GS Engineering and Construction, Spain’s Tecnicas Reunidas, Italy’s
Saipem, Chinese Shandong Electric Power Construction Corp (SEPCO), India’s Larsen and
Toubro (L & T), Taiwan’s CTCI and Britain’s Petrofac Taiwan’s CTCI said they had made a bid for
the project, declining to give details.
Hyundai Development Co Engineering & Construction said the company submitted the bid,
expecting results to be out at the end of the year or early next year. Saudi Aramco is implementing
a two-phase plan to expand its Master Gas System, built in the mid-1970s to gather and process
associated gas from oil wells for domestic industry. It is scheduled to complete the first phase of
the capacity expansion of system by the end of this year by installing facilities, including the
booster compressor stations. A second phase of expansion of the MGS will bring capacity up to
12.5 billion standard cubic feet per day in 2019.

Uzbekistan: LUKOIL launches 4.1BCFD Gas production facilities
at Gissar in Uzbekistan….. Lukoil
LUKOIL has reached a progress milestone at its South-West Gissar project in Uzbekistan
as it successfully launched the main production and process facilities there. These include a gas
treatment plant with the annual rated capacity of 4.4 billion cubic meters, a gas pretreatment unit
and four gas-gathering stations.
As a result, gas production at the Gissar fields cluster reached planned production level of 14
million cubic meters a day, or 5 billion cubic meters per year. As of today, there are 37 producing
wells.
Three hundred kilometers of high-voltage power-transmission lines, two power substations and
126 kilometers of roads were constructed. 64 thousand cubic meters of concrete were used at
various facilities, approximately 12 thousand tons of steel structures and over 4 thousand tons of
equipment were assembled and 286 kilometers of linear pipelines were laid.
Around 3,500 contractor workers and 250 employees of LUKOIL's subsidiary, LUKOIL Uzbekistan
Operating Company, over 350 pieces of special construction equipment were involved in the
active phase of the infrastructure development at the Gissar fields cluster.
LUKOIL entered the South-West Gissar project in 2008. The license area includes seven fields.
The Production Sharing Agreement (PSA) is until 2043. The participants of PSA are the Republic
of Uzbekistan and LUKOIL (100% share). LUKOIL produced 1.7 billion cubic meters of gas in
2016 (the company’s share equaled 1.5 billion cubic meters).

Mexico’s shale-rich Burgos Basin opens to private investment
for the first time ..U.S. EIA, based on Petróleos Mexicanos and Natural Gas Intelligence
In July 2017, Mexico’s national energy ministry (SENER) opened the onshore portion of the
Burgos Basin, a shale-rich basin in northeastern Mexico, for natural gas exploration and
development by private companies.
This is the first time non-state entities were offered access to the Burgos Basin for development
since the creation of the national oil company Petróleos Mexicanos (PEMEX) in 1938. SENER
hopes that private investment will help to reverse the decline in natural gas production and offset
decreasing PEMEX investment in the region.
Production from the Burgos Basin accounted for 15% of total natural gas production in Mexico in
2016, and the basin holds the largest undeveloped shale resources in the country.
Increasing production from the region would help meet growing natural gas demand, particularly
from new natural gas-fired generation in Mexico’s Northeastern region, and make Mexico less
reliant on natural gas imports in the long term.
Located in the state of Coahuila, south of the Rio Grande River, the Burgos Basin covers an
onshore area of approximately 24,200 square miles. Offshore, it extends onto the continental shelf
of the Gulf of Mexico.

The Burgos Basin is the southern extension of Texas’ Western Gulf Basin, which encompasses
the Eagle Ford shale play. PEMEX initiated exploration activities in the Burgos Basin in 1942 and
it has discovered some 227 fields, mostly rich in natural gas. The basin currently has more than
3,500 active natural gas wells in non-shale formations.
Many reservoirs in the Burgos
Basin have low permeability and
high decline rates typical for tight
formations, which require
significant investment from
PEMEX to maintain or increase
production. In response to
decreasing natural gas prices
over the past five years
and energy reforms introduced in
2014 that gave priority to oil
development, PEMEX has
decreased its exploration and
production spending in Burgos. In
2017, PEMEX plans to spend $51
million (0.9 billion pesos) in the
Burgos Basin, down 92% from the
$657 million (11.7 billion pesos) it
spent in 2012. At the same time,
natural gas production in the
basin has dropped by 32%, from
1.2 billion cubic feet per day
(Bcf/d) in 2012 to 0.87 Bcf/d in
2016, all from nonshale
formations.
Although PEMEX has conducted
shale exploration activities on its
own in the Burgos Basin, they
have yet to reach commercial
production, as many of the early
wells have low production rates.
The companies that were
awarded licenses in the Burgos Basin are expected to stabilize or reverse the declining natural
gas production in the region. High levels of production in the U.S. Eagle Ford shale play to the
north could indicate similar production levels in the Burgos Basin region.
The Mexican government is planning to open more acreage in Burgos and other shale basins to
private companies before the end of 2018.
Crude oil production at Mexico's Pemex hits 22-year low
Monthly crude production from Mexican national oil company Pemex fell below 2 million barrels
per day in July for the first time in more than two decades, according to company data released on
Wednesday.
Average crude output in July was 1.99 million bpd. The monthly average was the lowest level of
crude production for Pemex, officially known as Petroleos Mexicanos, since Hurricane Roxanne

severely disrupted operations in October 1995, pushing down output that month to 1.90 million
bpd.
Pemex has experienced a 13-year streak of declining oil output. Seeking to reverse the trend, a
landmark oil opening finalized in 2014 ended the firm's monopoly while allowing private producers
to operate their own fields for the first time in decades.
Scheduled maintenance on a major Floating Production and Storage Offloading vessel in the Bay
of Campeche, home to Pemex's most productive oil fields, contributed a loss of about 90,000 bpd
to the July total, according to a Pemex representative.
So far this year, average crude production stands at 2.01 million bpd.

US: Northwest heat wave leads to record levels of summer 2017
electricity demand..EIA, based on National Weather Service and National Centers for Environmental Information
Multiple record-breaking heat waves swept across the western United States this summer, with
the latest occurring in the Pacific Northwest from August 1–4, 2017. Coincident with the hot
weather, some of the largest electricity balancing authorities in the area experienced record-high
summer electricity demand on their systems.
In the region’s largest cities, the highest temperatures were seen on Thursday, August 3, when
Portland reached 105 degrees and Seattle reached 94 degrees. These highs were 23 degrees
and 17 degrees higher than the 30-year (1981–2010) average highs for that day for Portland and
Seattle, respectively. Despite the proximity of the cities, Seattle’s summer temperatures can be
notably lower than Portland’s because of the nearby Puget Sound and the Pacific Ocean’s
moderating effect on Seattle’s climate.

Bonneville Power Administration (BPA) is a federal power marketing administration that supplies
large volumes of hydropower to other balancing authorities in the region. BPA broke its previous
summer peak demand record of 7,861 megawatts (MW) from 2014 every day between August 1–
3, with the highest peak of 8,226 MW occurring on Wednesday, August 2, 2017.
Portland General Electric (PGE) serves about 45% of Oregon’s population, including most of
Portland and its metropolitan area. PGE set a new summer peak demand record of 3,967 MW on
Wednesday, August 2, only about 100 MW lower than PGE’s all-time peak demand of 4,073 MW
from December 1998.
Seattle City Light (SCL) serves the city of Seattle and, with Puget Sound Energy, Inc (PSEI), most
of its surrounding areas. These utilities saw higher demand during the heat wave than in the
previous two July–August periods but did not exceed their historical summer peak records, which
occurred in July 2009 when temperatures in the area reached 103–104 degrees.

Unlike most of the country, many electric systems in the Northwest are winter-peaking, meaning
their highest electricity demand usually occurs in the winter during the heating season. The
Northwest typically experiences mild summers, leading to lower cooling-related electricity usage
compared with other regions.
Source: U.S. Energy Information Administration, Electricity Data Browser
The Northwest region also has a relatively large percentage of homes without air conditioning,
further reducing the impact of hot weather on electricity usage in the summer. Although 89% of
homes in the United States have some form of air conditioning, only 34% and 70% of homes in
Seattle and Portland, respectively, have air conditioning.

NewBase August 24 - 2017 Khaled Al Awadi
NewBase For discussion or further details on the news below you may contact us on +971504822502 , Dubai , UAE
Oil Climbs as Stockpile Drop Allays Worries Over Summer's End
Bloomberg + Reuters + NewBase + FX
Oil markets were happy to hear that summer isn’t over just yet, as the U.S. government reported
another decline in crude and gasoline stockpiles.
Futures in New York gained 1.2 percent after the Energy Information Administration said
America’s crude inventories shrank for an eighth straight week, with gasoline supplies also falling.
Price gains have been largely undercut by production increases in past weeks.
“As we exit summer driving season, peak demand season, it’s good to continue to see draws,”
said Nick Holmes, an analyst at Tortoise Capital Advisors LLC in Leawood, Kansas, which
manages $16 billion in energy-related assets. “That will help support prices as we move into
refinery maintenance season.”
Investors have been watching U.S. stockpile numbers closely as the Organization of Petroleum
Exporting Countries and its allies take longer than expected to drain a global glut. The efforts have
been hindered by rising output from shale fields and countries like Libya, which is exempt from
OPEC-led cuts.
Oil price special
coverage

While the change in gasoline and crude inventories was largely in line with expectations, “you’re
still seeing continued reductions in the inventory balance over time and the market is responding
to that,” Adam Wise, who runs a $8 billion oil and natural gas bond and private-equity portfolio at
John Hancock Financial Services Inc. in Boston, said by telephone.
West Texas Intermediate for October delivery rose 58 cents to settle at $48.41 a barrel on the
New York Mercantile Exchange. Total volume traded was about 11 percent below the 100-day
average.
Brent for October settlement added 70 cents to end the session at $52.57 a barrel on the London-
based ICE Futures Europe exchange. The global benchmark crude traded at a premium of $4.16
to WTI, the widest since 2015.
The Bloomberg Dollar Spot Index fell as much as 0.3 percent. A weaker greenback boosts the
appeal of commodities as an investment.
EIA Report
U.S. crude stockpiles fell 3.33 million barrels to 463.2 million last week, the lowest level since
January 2016, the EIA data showed. Gasoline inventories declined 1.22 million barrels to 229.9
million.
But the question for many investors is whether stockpiles will continue to decline next month,
when refineries typically start going into maintenance as gasoline demand tends to drop after the
U.S. Labor Day weekend. Rising output from shale fields isn’t making things any easier. U.S.
crude output climbed by 26,000 barrels a day to 9.53 million last week, the highest since July
2015.
“The report was pretty bullish for crude,” Tamar Essner, an energy analyst at Nasdaq Inc. in New
York, said by telephone. However, the data “reinforces this theory that even amid this downturn,
crude production in the U.S. is ticking higher or stable. It’s not going lower.”
EIA: US Oil Inventories Drop By 3.3 Million Barrels
U.S. crude stocks fell last week and gasoline stocks were down as well, the Energy Information
Administration said on Wednesday.

• Crude inventories fell by 3.3 million barrels in the week ending August 18, compared with
analyst expectations for an decrease of 3.5 million barrels.
• Crude stocks at the Cushing, Oklahoma, delivery hub fell by 503,000 barrels, EIA said.
• Refinery crude runs fell by 104,000 barrels per day, EIA data showed. Refinery utilization
rates fell by 0.7 percentage points.
• Gasoline stocks fell by 1.2 million barrels, compared with expectations in a Reuters poll for
a 643,000-barrel drop.
• Distillate stockpiles, which include diesel and heating oil, rose by 28,000 barrels, versus
expectations for a 93,000-barrel increase, the EIA data showed.
• U.S. crude imports rose last week by 605,000 barrels per day.
NewBase Special
Coverage
News Agencies News Release August 24
– 2017

Halliburton and Microsoft Do Not Compute for OPEC
By Liam Denning
Say "platform" at an oil conference and you'll usually conjure up an image of some windswept
deck on a rig far from shore. Like so much else, though, technology is rewriting the energy
industry's dictionary.
Halliburton Co. and Microsoft Corp. on Tuesday announced a new alliance to "digitally transform
the oil and gas industry," which, as a phrase, feels as if it was written by an artificial intelligence
designed solely to set your teeth on edge. Before you click away, though, consider that this union
of Big Oil and Big Data is a big reason OPEC is doomed.
Contrary to conventional wisdom, the oil business is a high-tech one. You don't map out complex
rock formations thousands of feet beneath the ground in three or four dimensions and then drill
into them without advanced tools.
For example, Total SA, the French oil major, boasts the 19th-most powerful supercomputer in the
world, Pangea, which has clocked a speed of more than 5 quadrillion calculations a second
(technical note: pretty fast) according to The Top 500 List.
Speaking at a conference in Houston in March, Ashok Belani, Schlumberger Ltd.'s technology
chief, bemoaned the fact that the average well has less than 10 gigabytes of data associated with
it, equivalent to a couple of high-definition movies.
In a survey of more than 4,800 professionals conducted in late 2014, MIT Sloane Management
Review and Deloitte scored the oil and gas sector's "digital maturity" at 4.68 out of 10. As a
measure of how far the sector has embraced digital technologies, that put oil and gas toward the
bottom along with education, insurance and health care -- which is pretty depressing for an
industry stuffed with engineers and scientists.
This is changing, however, helped by the happy trend of falling technology costs and the less-
happy reality of lower oil prices. The latter has not only forced E&P companies to find cheaper,
quicker ways of producing oil and gas, it has forced Halliburton and its rivals to find ways of
boosting bottom lines:
Contractor's Blues
Profit margins for even the biggest oil field services providers have collapsed and show little sign
of returning to pre-crash levels in the high teens

This makes sense, unfortunately, because like their E&P clients, contractors tend to lose their
heads in a boom-and-boost capacity, like they don't know the meaning of the word "cycle." In this
crash, a surfeit of pressure-pumping equipment used for fracking has been a consistent theme, at
least until recently. And even areas of supposedly tight conditions, such as the sand used in
fracking, can result in sudden capacity expansions that send highflying stocks tumbling:
Sand in the Gears
Shares of sand providers rallied strongly at the end of 2016 but have tumbled amid concerns
about excess supply
The key to restoring margins sustainably isn't discounting to retain relationships with fickle E&P

firms or just building more capacity. It's helping those E&P firms work smarter to boost their
atrophied bottom lines and taking a slice of that for yourself.
The bigger contractors such as Halliburton and Schlumberger have been banging this drum
throughout the downturn on several fronts, such as standardizing processes and integrating
different services.
Digitization fits with this. EOG Resources Inc. is one of the more digitally savvy E&P
firms and actually has a chief information and technology officer. On the last earnings call, he
boasted about how the company's teams now have access to more than 80 real-time data
streams and sensors embedded in wells, giving them a constantly updated picture of what's
happening beneath the ground.
The killer app here, in every sense of the word, is providing crews and their managers with an
integrated platform; a suite of sensors and software communicating seamlessly, updating
constantly and available to all involved.
Halliburton already has such a platform, called DecisionSpace. Marrying it with Microsoft's cloud-
computing and artificial intelligence capability has the potential to not only take and organize more
of the data spewing from an E&P client's fields but use machine learning to make better decisions
about, say, when a vital piece of equipment needs to be replaced or how a fracking job could be
done more quickly and cheaply.
Developing these 21st-century platforms offers a new way to make brands like Halliburton count
for more. A similar logic drives Schlumberger's investment in its Petrel platform and Baker Hughes
merging into General Electric Co.'s oil and gas business, with the latter's Predix industrial
software. Partnering with companies like Microsoft not only brings in a tech company keen to push
its ever-expanding cloud capacity into a new market, it also offers credibility on issues like
cybersecurity, which are only becoming more important as wells become more connected.
For the likes of OPEC, though, this is not good. Its members have relied on sovereign control of
resources and delays in developing non-OPEC fields to influence prices.
As I wrote here, the advent of shale, with its faster schedules and an experience curve more akin
to manufacturing, has overturned this strategy. U.S. shale fields account for less than 10 percent
of global output, but they sway the whole industry because of what they represent: A vast
resource base where E&P firms have pushed down production costs, experimenting with new
techniques and technologies. This has spread, as technology always does, into other parts of the
business, such as deep water drilling.
The upshot is a more competitive global oil industry where survival rests on managing costs rather
than trying to manage prices. This has spelled deflation for oil markets already. Now, the
machines are coming.
To digitally transform the oil and gas industry
Microsoft and Halliburton have announced plans to enter into a strategic alliance to drive digital
transformation across the oil and gas industry. The relationship will combine the expertise of a
global leader in cloud and digital transformation with a global leader in exploration and production
(E&P) science, software and services.
'Halliburton is focused on delivering intelligent cloud solutions to drive the next generation of
efficient oil and gas exploration and production,' said Jason Zander, corporate vice president of
Microsoft Azure. 'We are excited to bring the power of Azure’s hyperscale, hybrid and global cloud
platform technologies to this alliance to enhance the value chain for our mutual customers.'

Researchers and engineers from both companies will leverage and optimize Microsoft
technologies in machine learning, augmented reality (AR), user interactions and Industrial Internet
of Things, as well as Azure's high-performant infrastructure and built-in computing capabilities to
deliver tightly integrated solutions
across the energy value chain.
Areas of collaboration include:
applying deep learning to reservoir
characterization, modeling and
simulation, building domain-specific
visualization for mixed reality,
creating highly interactive
applications and fueling the
digitalization of E&P assets.
As a first step in the alliance,
Halliburton has
made DecisionSpace® 365available
on Azure, enabling real-time data
streaming from IoT edge devices in
oilfields and the ability to apply
deep-learning models to optimize
drilling and production to lower costs
for customers. With the power of
DecisionSpace® on Azure, big
compute and predictive deep-
learning algorithms will help optimize
field assets and enable next-generation exploration and deep-earth models by using software to
fill gaps in sensor data, while reducing the number of steps and time required to render models.
'Halliburton is at the forefront of the digital transformation occurring in the E&P industry,' said
Nagaraj Srinivasan, senior vice president of Landmark and Halliburton Digital Solutions. 'We
believe open architecture and community-based innovation are necessary to drive this
fundamental change and we’re proud to work closely with an industry leader like Microsoft to
deliver tailored E&P digital business solutions to our customers across the globe.'
The breadth and depth of this collaboration will allow the companies to apply voice and image
recognition, video processing and AR/Virtual Reality to create a digital representation of a physical
asset using Microsoft’s HoloLens and Surface devices. Additionally, the companies will utilize
digital representation for oil wells and pumps at the IoT edge using the Landmark Field Appliance
and Azure Stack.
Microsoft Azure will also become Halliburton’s preferred public cloud provider for iEnergy®, the oil
and gas industry’s first global E&P cloud linking the oilfield to the office.

NewBase For discussion or further details on the news below you may contact us on +971504822502, Dubai, UAE
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Khaled Malallah Al Awadi,
Energy Consultant
MS & BS Mechanical Engineering (HON), USA
Emarat member since 1990
ASME member since 1995
Hawk Energy member 2010
Mobile: +97150-4822502
khdmohd@hawkenergy.net
khdmohd@hotmail.com
Khaled Al Awadi is a UAE National with a total of 25 years of experience in
the Oil & Gas sector. Currently working as Technical Affairs Specialist for
Emirates General Petroleum Corp. “Emarat“ with external voluntary Energy
consultation for the GCC area via Hawk Energy Service as a UAE
operations base , Most of the experience were spent as the Gas
Operations Manager in Emarat , responsible for Emarat Gas Pipeline
Network Facility & gas compressor stations . Through the years, he has
developed great experiences in the designing & constructing of gas
pipelines, gas metering & regulating stations and in the engineering of
supply routes. Many years were spent drafting, & compiling gas transportation, operation &
maintenance agreements along with many MOUs for the local authorities. He has become a
reference for many of the Oil & Gas Conferences held in the UAE and Energy program
broadcasted internationally, via GCC leading satellite Channels.

NewBase : For discussion or further details on the news above you may contact us on +971504822502 , Dubai , UAE
NewBase August 2017 K. Al Awadi

New base 24 august energy news issue 1065 by khaled al awadi

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